Workover Fluid Research Articles

Experimental and modelling studies on static sag of solid weighting powders in Polysulfonate workover fluids at high temperature and high pressure

The solid weighting material in a high-density workover fluid is prone to static sag. Existing experimental methods cannot predict the parameters of the settling stability of workover fluids at high temperature and high pressure (HTHP). Therefore, in this study, static settlement experiments were carried out using a novel experimental setup. The experimental setup enables the measurement of the density profile of heavy workover fluids at HTHP. A multi-parameter correlation equation between the sag factor and particle diameter, particle density, base fluid density, workover fluid density and rheological parameters, aging time, temperature, and pressure was obtained using dimensional analysis and multivariate nonlinear regression methods. The results reveal that the settlement stability of the workover fluid decreases with the increase in temperature and pressure. Based on the multi-parameter correlation, the predicted and the measured values were compared and verified. The error between the predicted value and the measured value was within 5%. The average prediction error was 1.68%, and the maximum prediction error was 3.8%. These results reveal that the model proposed in this study can effectively predict the static sedimentation stability of the solid weighted Polysulfonate workover fluids. Furthermore, the proposed correlation can guide the properties adjustment of the workover fluids to achieve the required sag stability. This work provides a new approach to predict and control the sag stability of the solid weighted workover fluids.

A low density micro-foam workover fluid for deep and ultra-deep wells with low-pressure coefficient and high inorganic salt

The leakage of workover fluid often occurs in the workover operation of low-pressure oil wells due to the pressure coefficient is generally less than 1.0, which leads to the slow recovery of oil well productivity or even failure to recover. The performance of workover fluid will directly affect the degree of damage and production of oil and gas wells. In this paper, SBX (Water+0.5% sodium dodecyl sulfate SDS+0.5% dodecyl dimethyl betaine BS-12 +0.7% polyurethane thickener XH-ZC-5) has been found to be a very effective temperature-resistant and salt-resistant low-density micro-foam workover fluid. Warning Blender experimental results showed that the half-life and foaming volume of SBX were 3084 min and 360 mL, respectively. Microscopic experiments demonstrated that the particle size of the foam gradually became smaller and the foam became denser with the increase of foam stabilizer XH-ZC-5 concentration. The foam stabilizing mechanism of XH-ZC-5 was mainly to keep the foam in a lower surface energy state by reducing the surface tension, and to increase the liquid viscosity of the foam to maintain the strength and elasticity of the liquid film. Besides, the tolerance of SBX to NaCl and CaCl2 was 20% and 15%, respectively. The half-life and foaming volume of SBX after thermal aging at 150 °C for 16 h were 2562 min and 430 mL, respectively. At the same time, the anti-oil pollution experiment indicated that SBX had good anti-pollution ability to crude oil when the crude oil concentration was less than 15%. The static suspended sand experiment showed that the settling time of carbonate sand particles with sizes of 2.1 cm and 1.7 cm in SBX foam was 550 times and 1160 times that in tap water, respectively. What’s more, the density and filtration loss of SBX at 150 °C were 0.64 g/cm3 and 9.6 mL, respectively. SBX was a non-Newtonian fluid at 150 °C, and the power-law model of the foam system was τ = 2.187ŕ0.419. SBX is of great significance to the workover operation of deep and ultra-deep wells with low-pressure coefficient and high inorganic salt.

Integrated reservoir, geology, and production data for reservoir damage analysis: A case study of the Miocene sandstone reservoir, Gulf of Suez, Egypt

Reservoir damage is considered one of the major challenges in the oil and gas industry. Many studies have been conducted to understand formation damage mechanisms in borehole wells, but few studies have been conducted to analyze the data to detect the source, causes, and mitigations for each well where damage has occurred. I have investigated and quantified the reasons and mitigation of reservoir damage problems in the middle Miocene reservoir within the El Morgan oil field at the southern central Gulf of Suez, Egypt. I used integrated production, reservoir, and geologic data sets and their history during different operations to assess the reservoir damage in El Morgan-XX well. The collected data include the reservoir rock type, fluid, production, core analysis, rock mineralogy, geology, water chemistry, drilling fluids, perforations depth intervals, workover operations, and stimulation history. The integration of different sets of data gave a robust analysis of reservoir damage causes and helps to suggest suitable remediation. Based on these results, I conclude the following: (1) Workover fluid has been confirmed as the primary damage source, (2) the reservoir damage mechanisms could be generated by multisources including solids and filtrate invasions, fluid/rock interaction (deflocculating of kaolinite clay), water blockage, salinity chock, and the high sulfate content of the invaded fluid, and (3) multidata integration leads to appropriate reservoir damage analysis and effective design of the stimulation treatment. Furthermore, minimizing fluid invasion into the reservoir section by managing the overbalance during drilling and workover operations could be very helpful. Fluid types and solids should be considered when designing the stimulation treatment and compatibility tests should be performed. Long periods of completion fluid in boreholes are not recommended, particularly if the completion fluid pressure and reservoir pressure are out of balance, as well as the presence of sensitive formation minerals.

Protective Workover Fluid for Biological Limestone Reservoir in Dagang Oilfield Technology Research

Due to the development of the biogenic limestone Cracks of reserves and dual-media, the pore permeability is larger different, the sensitivity is strong, and the risk of lost circulation is large, which leads to the serious formation pollution caused by the lost circulation. According to the reservoir characteristics, the temporary blocking system has been developed, Its temporary blocking component size expanded to 5μm∼2.0mm, Block size expanded from 0.2mm to 1.0mm, the limestone temporary blocking rate’s minimum is 90%, invasion depth of sand bed is less than 3 cm, temporary blocking component degradation rate is higher or equal to 90%. Excellent technical application, the average recovery period of the pump well was reduced from 7 days to 3.7 days, and the recovery rate was increased from 70% to 97%.

Workover fluid for the reconstruction of wells with reduced reservoir pressure

Opracowanie rekordu ze środkow MNiSW, umowa Nr 461252 w ramach programu "Spoleczna odpowiedzialnośc nauki" - modul: Popularyzacja nauki i promocja sportu (2020).

Improved understanding nanocomposite gel working mechanisms: From laboratory investigation to wellbore plugging application

Fluid loss is serious in low-pressure fractured reservoir. In this paper, the technique of wellbore isolation for temporary plugging is proposed to reduce the loss of workover fluid. Based on radical polymerization, the high-strength nanocomposite gel plugging agent was prepared by introducing nano-silica. Firstly, the strength properties of gel plug were studied through stress and strain evaluation, viscosity modulus test and wellbore sealing pressure evaluation, respectively. The working mechanism was revealed by infrared spectroscopy (FTIR), environmental scanning electron microscopy (ESEM) and differential scanning calorimetry (DSC) analysis. The study shows that under 50% compression strain, the compression capacity of the nanocomposite gel with 5% nano-silica is nearly three times higher than that of without adding nano-silica, and the thermal stability is improved by 38%, which has the potential to buffer the pressure of the liquid column in the bottom hole and perform good thermostability. Secondly, the actual wellbore simulation system confirmed its ability to seal the perforation zone. Result shows that the pressure-bearing gradient is 20 MPa/100m in the oil tube, and gel plug length can be designed according to the positive pressure demand. The addition of nano-silica makes the network of nanocomposite gel becoming denser, in favor to store more energy. The hydrogen bond generated in the nanocomposite gel increases its mechanical strength. Finally, the successful application of the nanocomposite gel for wellbore temporary plugging in a low-pressure carbonate gas well was summarized. This study provides an avenue to develop various nanocomposite gels for downhole jobs.

Formation damage evaluation of a sandstone reservoir via pore-scale X-ray computed tomography analysis

The incompatibility between workover fluid and reservoir rock is one of the causes of formation damage. Fines migration and clay swelling are considered as the major mechanisms responsible for formation damage, which results in declining productivity. However, there has been limited visualized evidence of pore structural changes during formation damage. This paper establishes a formation damage evaluation method for sandstone reservoirs based on X-ray micro-computed tomography (CT) analysis. We presented conclusive evidence for clay swelling and fines migration during workover fluid flooding and formation liquid flooding. Water sensitivity and flow rate sensitivity tests were performed on a Dongying sandstone (heterogeneous argillaceous sandstone) plug. In addition, the plug was micro-CT imaged before and after flooding with workover fluid and formation liquid at medium resolution (24 μm voxel size); the changes in core permeability and the associated changes in 2D and 3D pore space were analyzed. We found that the sandstone pore space was partially blocked by clay minerals and moving particles, leading to significantly decreased porosity (5.17%–4.19% for sample 1, 5.38%–2.76% for sample 2) and permeability (3.38 × 10−3 μm2 to 1.28 × 10−3 μm2 for sample 1, 13.30 × 10−3 μm2 to 3.15 × 10−3 μm2 for sample 2). This permeability decrease was caused by a decrease in the average pore radius and coordination number. Moreover, increased micro-CT intensity was measured by comparison of initial and final tomogram images, representing clay swelling & blockage of pores during the displacement and a generally lower porosity. This work visualized microscale formation damage, which reminds that incompatibility between workover fluid and reservoir rock damages formation seriously and the fluid injection rate should be lower than the critical flow rate when developing a reservoir with a strong water sensitivity and flow rate sensitivity.

Research on Protecting Formation Low-Damage Workover Fluid in Low Permeability Reservoir

During the workover treatment process, poorly compatible workover fluids infiltrating into reservoir could cause serious formation damage. To tackle the aformentioned issues, in this work, low-damage workover fluid was systematically studied. By investigating reservoir damage mechanisms, chemical property study, compatibility evaluation test and core flow test, we obtain three kinds of workover fluids suitable for different blocks in Nanpu oilfield. Attractively, JRYL workover fluid which contains antiswelling agents can effectively prevent water sensitivity, and the permeability recovery values of JRYL workover fluid to NP1-5 and PG2 core are 95.3% and 86.9%, respectively. JRYD workover fluid which contains antiswelling agents and anti-waterblocking agent can prevent both water sensitivity and water blocking damage, and the permeability recovery value of JRYD workover fluid to NP403X1 core is 89.4%. JRYJ workover fluid suitable for high pressure formation can prevent water sensitivity and water blocking damage, and the permeability recovery value of the JRYJ workover fluid to NP403X1 core is 95.1%. The actual field application in Nanpu oilfield indicates that these workover fluids can not only reduce the oil well recovery time after workover treatment, but also increase production recovery rate. These results display great potential to efficiently develop low permeability reservoirs.

Technology Focus: Formation Damage (February 2015)

Technology Focus Brant Bennion, in the Journal of Canadian Petroleum Technology Distinguished Authors series, titled his 1999 article on formation damage “The Impairment of the Invisible by the Inevitable and Uncontrollable, Resulting in an Indeterminate Reduction in the Unquantifiable.” This is a brilliant definition of formation damage because it reflects very well the lack of relevant data (in particular, permeability data) that are essential for adequate design of drilling and completion fluids. In addition, the opening sentence in Bennion’s article is as relevant today as it was in 1999: “Formation damage is a hot topic these days—with justifiable reason as we move to the exploitation of more challenging oil and gas reservoirs in tighter, deeper, and more depleted conditions.” In order to avoid some of the detrimental effects of formation damage, a key aspect is laboratory testing of representative core material under representative downhole conditions. Thin sections, dry scanning electron microscopy (SEM), cryogenic SEM, and X-ray diffraction have been used for a number of years to identify the main damage mechanisms, mechanical or liquid, contributing to the observed returned permeability measurement from coreflooding. High-resolution images can be obtained from dry and cryogenic SEM, but they offer only a limited view at any one time. One technique that has been applied recently to identify and quantify potential formation damage is that of microcomputed tomography (CT). This provides high-resolution scans of whole plugs and allows, for example, the identification of changes in pore structure because of fines mobilization, and the visualization of the filter cake after cleanup, depth of mud solids, and filtrate invasion. The combination of micro- CT with techniques previously used for formation-damage analysis is providing new understandings in the interaction of drilling and completion fluids with core material. One of the more frustrating aspects of coreflooding has been how to relate the results obtained to potential well-inflow performance. Computational fluid dynamics is one technique that appears to have bridged this gap. This technique incorporates the data obtained from coreflooding into a model that recreates the actual well geometry, depth of formation damage, mud thickness, and distribution of restrictions in the tubing, such as safety valves. With this approach, production rates can be obtained that provide useful insights into selecting appropriate drilling and completion fluids, for example. Enjoy the papers selected. Formation damage is still a “hot topic.” JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 165092 Case-Study Analysis of Formation Damage Induced by Brine Workover Fluid on Burcioaia Reservoir (Romania) and Research on Damage- Removal Methods by A. Dragomir, OMV Petrom, et al. SPE 165169 Formation Damage and the Importance of a Rigorous Diagnostic: A Case History in Nigerian Deep Water by Jean-Noel Furgier, Total, et al. SPE 169435 Integrated Analysis To Identify and Prevent Formation Damage Caused by Completion Brines: A Colombian Field Application by M.G. Jaimes, Ecopetrol, et al.

The Research and Application of New Low Density Nitrogen Micro Bubble Workover Fluid

Aiming at the need of coiled tubing sand washing operation for the low-pressure and leaking gas pool in Qinghai gas reservoir, we developed a kind of low density nitrogen micro bubble workover fluid technology, which is composed of a new type of composite foaming agent, temporary plugging agent, composite stabilizing foam agent and the nitrogen. Observing by a microscope, we can find that the micro bubble structure is composed of a core of gas, two membranes, three layers, which has high stability (higher stability than ordinary foam stability). The performance evaluation results show that, the temperature resistance of nitrogen micro bubble workover fluid is up to 120 ℃. Compression resistance can reach 20 Mpa. API filter loss is only 11.3 ml. The high temperature and high pressure filtration is only 16.6 ml. Anti-salt can reach 10%. Anti-calcium can reach 3% and the resistance to oil pollution is more than 15%. The recovery rate of core permeability is up to 89%. The system can not only reduce the fluid column pressure and reduce the pressure difference, but the formation of micro bubble in the leakage areas on the surface of formation is widespread, and has a certain strength and toughness, and also has a certain deformability matching leakage channel of formation, which can achieve the purpose of anti-leaking. This technology was applied in Qinghai gas field for 2 wells, with an efficiency of 100%. The sand washing operation was successfully completed, with no leakage. Key words : Low density nitrogen micro bubble workover fluid; Micro bubble; Qinghai gas field

The Kinetics Mechanism Analysis of Sulfur Depositions in High Sulfur Content Gas Reservoirs

The origin of particles which lead to reservoir damage in oil industry mainly includes internal generation and external invasion. The particles generated in reservoir include clays, mineral particles, deposits and particles which are separated out in physical and chemical effects. Particles of external invasion include invasions in the process of drillings and fracturing operations, particles in work-over operation and completion fluid operation, or debris which are carried by injection fluid (water, chemicals, etc.). The force of the particles has affected the seepage law in high sulfur gas reservoir. By analysis of the particle migration, sedimentary characteristics, and the force situation of sulfur particles, we will discuss dynamical mechanisms of sulfur deposition.

Deepwater Workover Experience With Extreme Hydrostatic Overbalance

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 134378, ’Deepwater Workover Experience With Extreme Hydrostatic Overbalance, 2002-2009’ by G. Myers, SPE, D. Cahill, SPE, P. Clay, SPE, B. Esquinance, B. Smith, SPE, and R. Zeringue, SPE, Shell E&P Co.; C. Davis, SPE, Shell International E&P; and T. Kenney, Crown Consulting, originally prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The full-length paper presents planning and execution details for fluid-loss control during workovers with “extreme-hydrostatic-overbalance” (EHO) conditions (i.e., between 1,500 and 4,000 psi). Actual results for several wells from three deepwater fields in the Gulf of Mexico (GOM) are included. The information is applicable to operators that face similar requirements to maintain well control throughout the workover, mitigate any damage to the installed sand control or reservoir, and complete removal of the fluid-loss barrier to re-establish production. Introduction For many years, the industry has dealt with large hydrostatic overbalances in a variety of ways during workovers. Onshore, operators of tight gas fields initially may pump fluid to kill the well for rig up, then add fluid intermittently during the job as required to work safely. Offshore, operators of shallow-water, higher-permeability fields may initially kill the well with seawater for rig up, then continuously feed or “let the well drink” seawater to maintain hydrostatic overbalance during the job. The full-length paper focuses on direct-vertical-access (surface tree) wells in deepwater GOM fields. These wells are characterized by high-permeability, thick sand intervals; downhole sand control; and very high fluid-loss rates after perforating or stimulation. Profitability is tied to maintaining high production rates without significant solids production. It is the combination of extreme hydrostatic overbalance, high permeability, downhole sand control, and high production potential that makes these wells so challenging. Subsea wells in deepwater GOM fields must be handled differently because of the potential for riser collapse, use of riser fill valves, and the daily cost of floating rigs. EHO is a term used to describe conditions significantly outside the normal. It is common to execute workovers in the GOM with 200- to 300-psi hydrostatic overbalance—that is, the difference between the hydrostatic-column pressure at the perforations and the near-wellbore reservoir pressure. Depending on the reservoir-drive mechanism, workovers in later life may be executed with 300- to 800-psi hydrostatic over-balance (moderate) or 800- to 1,500-psi overbalance (high). The term EHO is used to describe wells with 1,500-psi or greater overbalance and is not a precise definition. Depending on the job, 1,200-psi hydrostatic overbalance may require similar planning. To date, jobs have been planned with overbalance approaching 4,000-psi, typically using seawater as the workover fluid.

Study on the Workover Fluid Formula and Performance of the Prevention Reservoir

In the workover treatment of Yakela condensate gas field, the workover fluids are easily leaked, and many problems such as clay expansion, rate sensitivity, migration of fines, and change of wetting property will occur, which will induce serious reservoir harms. In the article, the performances of the existing workover fluid of the Yakela condensate gas field with high temperature and high pressure are evaluated, and the influencing factors harming the reservoir are analyzed and obtained, and the effective measures and methods preventing the reservoir harm are confirmed. The technical principle, material composing, performance index, and the evaluation of stratum liquid compatibility are introduced in the article. The result of performance evaluation indicates that the core return permeability of the workover liquid system can achieve above 80%, and it is an ideal low-harm workover fluid system.

PORE NETWORK MODELLING OF FORMATION DAMAGE DUE TO SUSPENDED PARTICLES

Formation damage caused by suspended particles takes place in various stages of drilling and production operations. The particles in drilling fluid, completion fluid, workover fluid, or injected water can clog the formation and cause severe reductions in productivity or injectivity. Related research has been conducted for years and the most widely used models are empirical, based on specific core flooding data. These models are easy to use; however, when they are applied to formations with different characteristics, the predictions are often rather poor.This work investigates a promising way to model formation damage at the pore level. Even though reservoir rocks have very different characteristics, they are all combinations of pore necks and pore bodies. In the proposed model, pore necks are represented by tubes and pore bodies are represented by globes to form a 2D network where particle deposition takes place. The pore size distribution is measured by porosimetry and assigned to the network. By adjusting the parameters of the pore necks and pore bodies, this pore network model can represent real porous media quite well. Surface deposition was considered to be the main mechanism of formation damage for small particles. The model was validated with lab test data and reasonable results were obtained. Compared with the empirical model, the pore network model could be applied to a much wider range of reservoirs.

Viscosity of the Workover Fluid FAPX

The physical properties of workover fluids are important in the success of workover operations, in particular, emulsion stability and viscosity. In this work these properties have been investigated using a direct emulsion of oil in water. Three emulsifiers were analyzed and their effects on emulsion stability have been measured both in terms of surface tension decrease and their hydrophilic-lypophilic behavior. An extensive investigation on viscosity was carried out under laboratory conditions and the results reported as isokoms in ternary diagrams. The experimental results were analyzed in terms of an Arrhenius-type equation. It is concluded that small changes in composition lead to large changes in the viscous properties of the workover fluid.

Completion and Production Results From Alternate-Path Gravel-Packed Wells

Summary A successful gravel pack requires two things: perforations packed with gravel-pack sand and a completely packed annulus. Failure to obtain either one can result in low productivity and/or a sand-producing gravel pack. Alternate-path gravel packing ensures that the annulus will be completely packed and that all perforations taking fluid will be packed with gravel-pack sand. Alternate-path gravel packing has provided long and highly productive completions without any sand production. This paper presents completion data and production results from 39 wells completed with the alternate-path gravel-pack technique. The completion data include completion length, net perforations, carrier fluid, sand placement outside casing, workover fluid, and return rate during packing. Production results include qualitative discussion of all completions with quantitative results, including permeability-thickness product and skin on select completions.

Installation of 2 7/8-in. Coiled-Tubing Tailpipes in Live Gas Wells

This paper describes a technique for installing 2 7/8-in. coiled tubing as tailpipe extensions below existing production packers in live gas wells. It also covers the use of coiled tubing as a way to complete wells. Large savings in rig time and deferred production have been realized with this technique. Fluid losses to the formation do not occur, and no expensive rig time is needed to kill or clean up the wells, as required for conventional workovers below existing production packers. This technique is particularly applicable in depleted reservoirs that could be impaired by traditional workover methods.

Improving Oilwell Stimulations With Compatible Oils

Abstract Crude oils, diesels and similar distillates are often considered to be inert stimulation fluids for use in oil wells. In fact they may contain or create plugging materials which can reduce or destroy permeability. It is common knowledge chat produced crudes may contain clays, fines, sulphur, salt, organic debris, asphaltenes, as well as any chemicals added to assist production. Although crudes are still used to hydraulically fracture wells because of low cost, distilled oils are commonly used in an attempt to avoid the mentioned problems. However, clean fluids such as diesel and condensate are still incompatible with some crudes and particularly the asphaltic crudes common in western Canada. Special refining can produce oil which is very compatible with, crudes. One such oil is available at a cost comparable to diesel and has been used as a workover fluid, fracturing fluid, and acidizing spacer. Results of more than one year of field evaluation confirms that the fluid is practical to use and is meeting our expectations. Laboratory results and theoretical background are also provided. Introduction It is the intention of this paper to discuss some important aspects of the use of oils in well completions. Most ideas are relatively familiar to many readers, however, they will be reviewed in reference to a new product which has become available. In the majority of cases oil is used because of concerns over formation damage. In such cases, oil is often regarded as relatively benign in comparison to water-based fluids. There are many good reasons to believe this. The main ones are listed as follows:—Fresh water in contact with any smectite clays in the formation will be absorbed into the clay structure and cause swelling. The swelling restricts the pore throat to reduce the permeability.—Kaolinite clays and other migratable fines which are water wet or are loosely attached to the pore surface will only move within the connate water phase. When water invades a formation with irreducible water saturation, the fines will then become movable and begin plugging the pore throats.—Water, being the most universal inorganic solvent known, can carry a variety of chemicals, cations and anions into the formation. Incompatible water, sometimes even with very low concentrations of contaminants, can cause a variety of precipitates, emulsions and sludges which can reduce or destroy the formation permeability.—Even a very low percentage of fines contained in water can easily plug perforations or the formation. This point can more easily be appreciated since very dirty water is recognizable with the naked eye. It should be kept in mind that occasionally clear water contains enough fines to do serious formation damage. In contrast oils are perceived, although sometimes inaccurately, to have the following behavior:"Oil does not react with smectite clays to cause swelling. Further to this, oils are not expected to react with any clays present to produce detrimental results. ""Oil does not open the door for lines migration to begin. "

Early-Time Pressure Buildup Analysis for Prudhoe Bay Wells

Summary A method of pressure buildup analysis is presented that distinguishes between two possible reasons for the decline in a well's productivity-near-wellbore damage and permeability loss in the well's drainage area. An extensive application is discussed for wells in the Prudhoe Bay field. Heterogeneity of this reservoir is such that semilog analysis methods are not reliable for identifying wells in need of remedial workover. Introduction The production rate of individual wells in the Prudhoe Bay field can decline for a variety of reasons, including workover damage, formation-water precipitate, fines migration, limited drainage area, and gas saturation. Calcium chloride brine was used originally as a workover and packer fluid. This brine, when mixed with formation water, precipitates calcium carbonate, which can practically plug the perforations and near-wellbore formation. Matrix acidization with hydrochloric acid gives only temporary relief. Carbonate scale forms again when the residual workover fluid contacts formation water or CO2 gas from crude-oil production. Fines also migrate to the wellbore. These particles of clay and/or microporous chert plug the perforations, which apparently leads to an insidious type of pressure buildup behavior. The perforation tunnels, perhaps, tend to collapse and thereby compress any fines and/or scale present. This compaction would increase as the amount of drawdown increases. When such a well is shut in and the pressure recovers, this compaction reverses to give a pressure-sensitive near-wellbore damage that can dominate a 24-hour buildup test entirely. Well 6 in Ref. 1 appears to be an example of such a situation at Prudhoe Bay. Factors other than true damage can cause production falloff. Prudhoe Bay field contains a number of mapped faults that limit the drainage area of nearby wells. Relative permeability can also reduce oil production. Since the field has an associated gas cap, the crude oil is at or near its bubblepoint pressure. Consequently, most wells flow at bottomhole pressures (BHP's) below the bubblepoint. These wells will have a near-wellbore region with gas saturation. This reduces relative permeability to oil in the near-wellbore region. Measured relative-permeability curves show that at the minimum mobile gas saturation of 5%, relative permeability to oil is decreased to about two-thirds of its value at zero gas saturation. With continued production, the zone of mobile gas saturation will expand sufficiently to give a measurable drop in productivity accompanied by an increase in GOR. Almost 700 buildup tests have been run in the Prudhoe Bay field. High-precision gauges are used consistently. The ambiguous interpretations of these tests, however, have generated confusion. One interpreter may claim a well is undamaged while another maintains that the well is damaged. Supposedly undamaged wells have been acidized to give threefold rate increases. We believe this confusion arises from attempts to apply Homer-type buildup analysis methods-or slight modifications thereof-to data from a reservoir that departs significantly from the model implicit in the Homer method. The Prudhoe Bay field has both a gas cap and an underlying aquifer. To provide distance from these contacts, the oil zones are usually perforated in only a portion of the net pay. This complicates a Homer-type analysis. Additionally, the formation is a complex sequence of sand-shales resulting from either braided stream or mouth-bar depositions. The sands are separated by shale stringers of widely varied thickness and of generally unknown permeability and lateral extent. As discussed in Ref. 1, gas-cap pressure support can interact with reservoir heterogeneities to give a bewildering and nonunique variety of distortions of the middle-time region so essential to a Homer-type analysis. No attempt is made to identify a middle-time region in the method described in this paper. Instead, early-time, afterflow-dominated buildup data are analyzed to determine whether productivity decline can be attributed to wellbore damage alone. In this paper we first give some comments on the method. This is followed by examples from buildups taken in the Prudhoe Bay field. The method consistently accounts for well productivity behavior. For some examples, the Homer-type analysis is completely satisfactory. In other examples, the Homer approach gives confusing and inconsistent results. Finally, there are examples from a sequence of tests on the same well that produce impossible results by Homer analysis. It is this very lack of consistency that we hope to eliminate. While we concentrate on tests from Prudhoe Bay, the general problem is not unique to this field. This is illustrated by our first example. JPT P. 311^

Fluid-Loss Control Through the Use of a Liquid-Thickened Completion and Workover Brine

Summary A new liquid thickening agent has been developed for controlling fluid loss of clear brines. This control is of critical concern during the completion or workover of an oil, gas, or service well. Many clear brines are expensive (up to $800/bbl for some concentrations). The loss of these fluids to the formation can become a significant completion/workover expense. From a safety standpoint, the loss of clear brines to a formation may create a reduction in hydrostatic pressure, which would increase the potential of a well kick or blowout. The newly developed agents function in brines with densities from 9.1 to 19.2 lbm/gal. They are superior to the traditionally used polymer because they start to build viscosity instantly, without the formation of "fish eye"s. The viscosity developed in the clear brines through the addition of these materials can be broken easily at the surface by the addition of small amounts of commonly available breakers. Brines containing this polymer show little or no permanent return permeability damage. The properties of the materials as fluid-loss-control additives in clear brines, their nondamaging characteristics, and rheological properties of the thickened brines are described. Case histories support the advantages of these properties. Introduction Fluid-loss control of clear brines is of primary concern during the completion or workover stage of an oil, gas, or injection well. The clear brines used in completions and workovers typically contain KCl, NaCl, CaCl2, CaBr2, and ZnBr2, or combinations of these salts, and range in density from 8.4 to 19.2 lbm/gal. These brines cost from a few dollars for the least-dense brine to about $800 for a 19.2-lbm/gal brine. The loss of these relatively high-cost, clear brines to the formation can be of significant importance when attempts are made to minimize completion and workover expenses. Loss of fluid level, resulting in a decrease of hydrostatic pressure on the formation, which exposes the rig and personnel to the danger of a well kick or blowout. Fluid-loss-control mechanisms when clear brines are in use have traditionally included (1) reducing the density of the completion or workover fluid, thereby imposing less hydrostatic pressure on the formation, (2) adding solids such as graded CaCO3 particles, FeCO3 particles, or sized rock salt, and (3) increasing the viscosity of the clear brines by adding dry polymers such as guar gum, hydroxylpropyl guar, xanthan gum, and (most commonly) hydroxyethylcellulose (HEC). These methods have been used independently and in combination with one another.1–4