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Abstract This paper describes the use of an innovative high-performance water-based drilling fluid system in south Europe. The novel drilling fluid allowed to successfully drill a sidetrack in a deep, high pressure-high temperature (HP-HT) well, in an area where low toxicity oil-based drilling fluids had been used in the past, due to the adverse drilling conditions. Comprehensive laboratory testing carried out to customize the drilling fluid formulation during the well planning phase, was complemented by further testing conducted during drilling operations. An obvious advantage of this system is its simplicity. It is composed mostly of liquid additives that allow a quick and easy preparation at rig site. The system is also compatible with the full range of mud densities, while exhibiting consistently superior lubricity characteristics. A tailored version of the system for this sidetrack well in southern Europe, required a heavy weighted fluid (up to 2.06 SG) to provide sufficient hydrostatic pressure for well control. The formulation included a high temperature rheology modifier that improved fluid stability at temperatures up to 160°C at total depth. A high performance lubricant was added to the system to improve drilling rate, while using an advanced steerable drilling system. Lubricity coefficients were monitored and recorded daily at rig site using a standard industry accepted ring and block type lubricity tester. The lubricity values fell in the range traditionally associated with oil-based mud usage. The successful sidetrack operations were completed with very good performances. Introduction Drilling fluids can influence all processes of well construction and operation, since incompatibility between the selected fluid and geological conditions yields many undesirable consequences in terms of drilling issues, quality of the production zone and economical performances. This is even more "true" when operating in complex drilling conditions, such as those described in this paper. In particular, one of the first applications of an innovative high performance water-based mud (HPWBM) outside the United States - it had been previously used only once in Europe - is reported herein, which made it possible to successfully drill a challenging sidetrack within a deep, high pressure-high temperature (HP-HT) well, in hard and tectonically-stressed formations. The HPWBM, optimized to the specific field conditions, met several standards for effectiveness: high lubricity, stability at high temperatures, little tixotropy, resistance to solids contamination. The fluid represented a big step forward in reducing the environmental impact, while providing performances comparable to those of low-toxicity oil-based muds used in the area for the last 20 years, as the only means to overcome the difficult drilling conditions. The reservoir is characterized by a white light brown dolomite of the Triassic age, and has two main hydrocarbon zones, an upper and a lower one. The sidetrack's target was the upper reservoir, which is an isolated fault block in the west area of the field resulting from a series of tectonic discontinuities, that had remained undrained by the previous operations. The depth of target reservoir was between 5500 and 6000 m, with a temperature of up to 160°C and pressures over 1000 kg/cm2 at total depth. In the offset wells, these demanding conditions, combined with the high formation hardness and the significant tectonic stresses, had leaded to such drilling issues as high torque, low rate of penetration (ROP) and wellbore instability. Instead, in the case described in this paper, the usage of the HPWBM, in combination with an advanced steerable drilling system, enabled the sidetrack to be successfully executed without incidents.

A new wire-line formation resistivity imaging instrument employing a ‘two-electrode’ measurement configuration has been developed for application in low-resistivity formations drilled with non-conductive (oil-based) mud. A detailed explanation of the instrument and measurement principles is provided. Modeled synthetic responses and field examples are shown. The high-spatial resolution of a ‘two-electrode’ arrangement has been well documented for nearly 25 years. The lower formation resistivity limit in oil-based mud boreholes for prior devices often precluded realizing their benefits in many important offshore deep water plays, such as Malaysia, Gulf of Mexico and elsewhere. The new instrument employs multi-frequency impedance measurements to overcome this limitation. The impedance measurements produce two image logs: a real-part impedance image that is calibrated to yield formation resistivity and an imaginary-part impedance image that conveys information about image quality. The instrument employs six individually-articulated pads each containing ten sensor electrodes that provide a 75% surface coverage in an 8½ inch borehole. Typical spatial-resolution is better than one-half-inch vertically and one-eighth inch azimuthally. Pad-to-pad depth off-set is less than 6 inches, assisting to maintain borehole coverage in the presence of common instrument rotation during logging. Field examples from typical logging environments found in offshore Malaysia are presented. Detailed geologic features such as thin-beds, slumping, cross-bedding, faulting and fracturing in low resistivity depositional environments are clearly resolved.

Abstract Drilling the Gotnia formation in Kuwait has long been a drilling fluids challenge due to its sharp contrast in lithology of salt/anhydrite interfaces. Presence of this salt layer below 13,000 ft. with a thickness of 700–1,200 ft. in deep wells makes this formation more plastic in nature due to high pressure and temperature. There is a fine line between kicks and total loses in this fractured formation. Hole instability, stuck pipe, total loss, well control, acid gases and H2S are frequent problems while drilling this section. High pore pressures exist, requiring mud weights ranging between 18.5–21.5 ppg. With this mud weight range in salt drilling, there are limited options available with the drilling fluid to ensure bore hole stability. Drilling fluids design, loss control and well control are massive tasks. Mud weight management with the knowledge of formation stresses, maintaining lowest possible rheology and managing the salt dissolution to avoid well bore closure/instability are key factors in avoiding complications in these deep wells. OBM is utilized to drill this formation due to the insolubility of salt in oil. Historically, this formation was drilled with lower oil/water ratios resulting in high rheology along with higher mud weights causing frequent mud losses and stuck pipes. Maintaining high oil/water ratio helped to overcome the problems associated with rheology and hydraulics. Salt rapidly reduces electrical stability and oil wettability in OBM. Emulsion stability was increased as a precaution to the extremely fine particles created through salt re-crystallization which has detrimental effect on stability. Fresh water in the water phase helps to minimize salt saturation and crystallization. This paper describes the drilling fluids challenges faced while drilling the Gotnia formation and the progress made over the years to drill this formation successfully.

The tight deep carbonate reservoirs of Oxfordian age in North Kuwait consist of tight limestone interbedded with organic rich shale layers. The overall matrix porosity is generally very low and the production is mainly from fractures in the crestal part of main structures. Borehole images are routinely acquired in vertical to moderately deviated wells drilled with oil-base mud for fracture characterization.For detailed fracture property evaluation, a highly deviated pilot hole was drilled with water-base potassium formate mud for the first time across the reservoir section and drill-pipe conveyed high-resolution electrical borehole image data was acquired. The upper half of the interpreted interval showed potential open fractures sets, NE-SW striking fracture set was most abundant. An advanced fracture segment extraction workflow was used to determine porosity and aperture of different fracture sets.The first horizontal well was then drilled as a lateral in the target reservoir with oil-base mud restricting direct computation of fracture properties. The electrical and acoustic images in OBM indicated fracture concentrations at quite a few places along the horizontal well trajectory, the most conspicuous occurring at the zones where heavy mud losses were encountered while drilling. A 2D litho-structural model was constructed along the well trajectories using the dip data and open-hole logs to correlate finer carbonate and organic shale layers and fracture distribution across the layers. This workflow permitted extending fracture properties along horizontal well as well.Finally, a high-resolution 3D structural model was constructed using outputs from previous workflows and data from two nearby vertical / less deviated wells. The final model showed a folded structure, which was absent in the existing model of the field. Thus the innovative workflow provides a means to generate an accurate structural and fracture model for the reservoir, integrating the fracture characteristics of the individual sub-layers with the main fracture corridors.

The current paper represents an overview of the automation model for drilling fluid mixing and is based on thesis works of (Nafikov 2011) and (Glomstad 2012). The first part of investigation is based on a model developed with the help of MATLAB® and SIMULINK® softwares. The simplified mud circulation model consists of downhole and mud mixing systems. The well is divided into control volumes to imitate the moving of drilling fluid inside the drillstring and the annulus and to include disturbances such as production of cuttings and mud losses to the formation. The possibility of monitoring the downhole pressure is included as well. Mud mixing system is represented in a way of addition of chemicals for mud treatment, i.e. viscosifier (bentonite), densifier (barite) and the mud dilution property with the help of water addition. The addition of all chemicals is controlled by PID controllers. Mud mixing and downhole systems interact between each other during simulations. When fluctuations in a form of cuttings or mud losses occur in the dowhole system, the mud mixing system adapts all PID controllers to keep the desired mud properties. The performance of the model is shown in the case of closed-loop simulations. Obtained results show the expected behavior of all variables and the possibility of automatic control. The second part of investigation will look at two principles for control of the mud mixing: cascade control and model predictive control. Compared to conventional PID-controllers with a single feedback loop, the cascade structure can utilize measurements both in the mixing tank and where the mud flows out of the well together. Continuous measuring of the mud properties is assumed. Also a controller based on model predictive control has been designed and tuned by using SEPTIC, an MPC tool developed by Statoil. The MPC controller calculates optimal inputs by minimizing a cost function subject to process constraints, defined priority levels and deviation penalties. Calculations are based on density and viscosity models found by looking at open-loop simulations of system responses to a change in different input variables. Closed loop simulations have been performed using both MPC and cascade controllers. A model for the well, "WeMod", is provided by IRIS and simulates the behavior of an actual well so it is seen how downhole conditions influence the density of the mud.

Wellbore strengthening techniques have been used in recent years to increase the capability of wellbores to maintain higher pressures. By increasing the fracture resistance of formations, operators can save rig-time and large volumes of drilling fluids. The Luna-41 well, offshore Italy, intersects a critical interval comprising high pressurized formations overlaying a lower pressure depleted zone. The initial plan for the well was to divide this interval into two separate hole sections using two different mud systems. A casing string would have been set to isolate the shallower high pressure region followed by an expandable liner to isolate the over pressured shales laying above the depleted reservoir level. An alternative design was proposed that required only one fluid system and a single casing string, thus saving an expandable liner. Thanks to the wellbore strengthening application and the proprietary continuous mud circulation device, the accomplished well program allowed an 8-day rig-time reduction and a 3-MMUSD cost saving. A specific modelling tool developed for wellbore strengthening applications was used to assist with fluid design. The tool calculates the width of microfractures induced by differential pressure and the Particle Size Distribution (PSD) of carbonate materials required to plug such microfractures and ultimately strengthen the wellbore. The mud formulation for Luna-41 was tested in the laboratory using a Pore Plugging Apparatus (PPA) and aloxite discs with pore sizes corresponding to the calculated microfracture width. The fluid used to drill the critical interval was a salt saturated system based on polyglycerol complex and supplemented with a polyamine inhibitor. The field application was a success. The depleted zone was drilled without incurring lost circulation. This paper describes the results of the field application as well as the fluid engineering process and laboratory testing to highlight the benefits - such as accessing depleted reservoirs and saving casing strings - that wellbore strengthening combined with a continuous mud circulation system can bring to the industry.

Lost circulation caused by low fracture gradients is the cause of many drilling related problems. Typically the operational practice when lost circulation occurs is to add loss circulation materials (LCM) to stop mud from flowing into the formations. To improve the treatment for lost circulation caused by low fracture gradients, especially designed materials in mud system are used to seal the induced fractures around the wellbore. This operation is in the literature referred to as wellbore strengthening that has been found to be a very effective in cutting Non-Productive Time (NPT) when drilling deep offshore wells. Size, type and geometry of sealing materials are debating issues when different techniques are applied. Also the phenomenon is not truly understood when these techniques applied in different sedimentary basins. This paper presents development and simulation results of a three-dimensional Finite-Element Model (FEM) for investigating wellbore strengthening mechanism. This study also describes a procedure for designing Particle Size Distribution (PSD) in field applications. To better understand the numerical results, the paper also reviews the connection between Leak of Tests (LOTs) and wellbore hoop stress and how these LOTs can mislead in fracture gradient determination. A comprehensive field database was collected from different sedimentary basins for this study. Results demonstrate that the maximum attainable wellbore pressure achieved by wellbore strengthening is strongly controlled by stress anisotropy. Results also show that Particle Size Distribution (PSD) of wellbore strengthening should be designed in order to seal the fractures close to the mouth and at fracture tip. This will result both in maximizing hoop stress restoration and tip-screening effects. In addition this model is able to show the exact fracture geometry formed around the wellbore that will help to optimize the sealing materials design in wellbore strengthening pills. To support numerical modeling results, near wellbore fracture lab experiments on Sandstone and Dolomite samples were also presented. Laboratory experiments results reveal importance of rock permeability, tensile strength and fluid leak-off in wellbore strengthening applications.

The popularity of formate-brine drilling muds continues to increase as a result of the benefits in the drilling and completion stages of well construction, as well as the lessened environmental impact when compared to some other muds. Growth in use of these muds has caused operators and service companies to re-examine environmental correction algorithms because of the substantial effects these mud systems can have on nuclear logs. In addition, because formate muds generally contain lower solids than conventional muds, they can be strongly invasive. Thus, the influence of formate muds on LWD logging measurements includes both borehole environmental effects to be corrected and formation invasion effects that affect log interpretation. A combination of laboratory experiments and Monte Carlo simulations have been used to develop a better understanding of the influences formate muds have on LWD gamma-ray, density, PE, and neutron porosity logs. Several hundred lab experiments and numerical simulations have been conducted in this investigation to fully characterize LWD responses to formate muds for families of sensors comprising two collar sizes used in a large range of hole sizes. The results were used to develop borehole corrections for the nuclear logs. Formate brines are formulated to achieve a desired fluid density by using a mixture of dissolved compounds: sodium, potassium, and cesium formate. In some instances, the mixture results in a fluid with a substantially lower-than-normal hydrogen index. The mud may also have a larger-than-normal potassium concentration. Because invasion consists of nearly the whole formate mud, correct log evaluation in porous, permeable formations requires interpretation techniques that are beyond the scope of customary borehole corrections. We have taken lab measurements to attempt to quantify the effect of this invasion on LWD tool responses.

Hundreds of wells have been drilled since the early 1900's at the Putumayo basin in southwest Colombia. ECOPETROL (NOC) used traditional mud systems: lignosulphonates, potassium chloride, and finally lime or gypsum mud systems, all of them designed to manage exposure to anhydrite, a common mineral in the drilled formations. The calcium contamination adversely affects mud system properties, resulting in hole instability and frequent stuck pipe events. Because of these issues, the operator considered using oil base mud (OBM) in a very environmental sensitive area. The OBM would generate undesirable waste and there were uncertainties about its performance, since few wells in the area had been drilled with OBM and the results were not very successful. Therefore, for drilling operations on the ECOPETROL Sucumbíos No. 5 well, a completely new high performance water base mud (HPWBM) was proposed and accepted. The new chemistry eliminated the use of bentonite and included a new flocculation inhibition mechanism, as well as new and powerful polymers. The system demonstrated that calcium and anhydrite were not a problem any more and the well was drilled in record time. More importantly, to the operator was able to evaluate the productive formations by running electrical logs, an operation that was normally cancelled because of severe hole problems. Casings strings were set and cemented per the well program and the well was completed as planned. This paper presents the design state of the HPWBM, its performance while drilling and charts and graphics comparing the changes against the historical values recorded in the area.

Diutan biopolymer has recently been introduced for drilling with coiled tubing on the North Slope of Alaska. Diutan biopolymer has replaced a xanthan biopolymer based mud system when drilling new sidetrack laterals from existing wells and also in well servicing with non-rig coiled tubing operations. This change in fluid systems was made by replacing the existing xanthan biopolymer used in the solids free mud system with a diutan biopolymer. The new diutan based solids free mud has shown improvements in several areas thus providing a significant performance advantage. Coiled tubing drilling (CTD) has been conducted in Alaska since 1994 with over 600 sidetrack laterals drilled to date. For the majority of these wells a solids-free mud system was used to drill in either an overbalanced or managed- pressure drilling mode. The solids-free mud used was based on a xanthan biopolymer. In 2009 planning for more difficult well candidates suggested that the existing xanthan drilling fluid systems would be inadequate for drilling certain wells without exceeding acceptable working pressures in the coiled tubing or surface equipment. The higher pump pressures expected, along with acceptable coiled tubing design parameters associated with this higher pressure demonstrated the need to modify the drilling fluid. The standard solids-free mud was modified by replacing the xanthan biopolymer with diutan biopolymer. This new system demonstrated a 20% reduction in pump pressure, better hole cleaning, a higher tolerance to the pH changes related to cementing operations and longer fluid system life. This paper will document the development of the diutan reservoir drilling fluid (RDF) system, including laboratory testing, field testing, a comparison to the xanthan based RDF, and the results of drilling actual wells. This new drilling fluid system has been in use now since July of 2009 and is the preferred drilling fluid used for coiled tubing drilling and well servicing in Alaska.

With increased concerns over the environmental issues regarding the use of oil-based mud (OBM)s, drilling companies in Iran are moving towards implementing less harmful water-based fluids. Due to low toxicity to the environment, effective shale inhibition and considerable cost savings, water-based glycol muds have the highest prospects as alternatives to OBMs in Iranian oilfields. However, designing water-based muds for drilling low-pressure shales may involve a compromise between mud weight optimization and overall environmental and economic advantages offered by these systems. The present study will focus on optimizing the weight of a glycol mud by emulsifying oil in the system and comparing its performance, environmental compatibility and cost with OBMs used in drilling low-pressure zones in Iranian oilfields. Properties of glycol solutions in the presence of oil were also evaluated. An emulsified glycol mud and an OBM with densities of 60 PCF were prepared and compared for their rheology and shale recovery. The shale recovery tests were conducted using shale samples from Maroon oilfield. Possible effects of contamination on the performance of the system were also studied. The glycol system was then treated to recover its diesel content. Overall, the laboratory data were convincing. With very low filtration rates, the emulsified glycol system is a candidate to replace OBMs in reservoir sections. Shale recoveries were comparable to those of OBMs. Compared with a similar OBM, considerable cost savings can be made and the system is more environmentally friendly. However, rheology was more difficult to control and the system was susceptible to contamination.

It is a common occurrence worldwide to have hole washouts while drilling with water-based mud. There are several reasons for this and until a concerted effort is taken to address the issue, such holes are bound to develop. Some of the problems that large washed-out holes cause are poor hole cleaning while drilling the hole, increased chances of stuck pipe, poor wireline log quality, bad zonal isolation after cementing primary casing strings, and loss of production due to inadequate zonal isolation. This paper discusses custom-designing water-based systems to address the problem of washed-out holes and wellbore stability. It details the laboratory testing performed on cores and drill cutting samples from the drilled intervals to assess the suitability of appropriate chemicals. The primary study concentrated on understanding the shale inhibition process using water-based fluids. The mineralogical compositions of the shales from the drilled areas were analyzed and tested with various base fluid types and additives. The recommendations generated from these studies were implemented in high temperature wells drilled by this operator. The results obtained from drilling these wells have been reduced hole wash-outs and stable wellbores. According to conservative estimates, the problems resulting from shale instability costs the petroleum industry over half a billion dollars per year. The learnings from this paper should help other operators overcome such issues and cut down on non-productive time and expenditures.

The North Slope of Alaska has billions of barrels of heavy original oil in place (OOIP) residing in largely undeveloped reservoirs. Despite this large volume of heavy oil in place, the majority of reserves development on the slope to date has been focused on light crude. However over the past few years, operators have begun to develop the North Slope's vast heavy oil resource base. Recently, an optimum drill-in-fluid/formation damage minimization study was undertaken by ConocoPhillips, BP, and its partners in order to determine the optimum reservoir drilling fluid for the heavy oil sands in order to maximize well productivity and project value. This paper will provide an in-depth look at the drilling fluid design, laboratory testing, and productivity analysis associated with determining the optimum reservoir drill in fluid (RDF) for the West Sak, horizontal, multi-lateral, extended reach, field development. Lab test results to be reviewed will include: Crude Compatibility Lubricity (steel to steel & rock to steel) Shale Stability General Rheology Mud Filtrate invasion tests with core to determine Return Perm Filtercake Removal tests w/ceramic disk tests to determine return permeability and removal effectiveness With the lab test results, well productivity calculations will illustrate why an oil based mud (OBM) was determined to be the optimum drill-in-fluid for West Sak. Lab tests and inflow performance modeling show injectivity and productivity improvements associated with reducing water based filtrate invasion and permeability reduction due to water and ineffective filtercake removal. Results show that the overall process of integrating the drill-in-fluid, completion design, inflow performance modeling, and operations procedures should be considered a best practice and an example of how an integrated study ultimately provides a field development with the best project value. Using the current field development economic model, this process added reserves, improved project NPV & IRR and maximized project economics

Drilling Heavy Oil Sands are traditionally fraught with many technical challenges. Stability of the wellbore, accretion of the tar on drill string and solids control equipment, torque-drag considerations, extreme temperature conditions, as well as the handling of oily solids are just some of the challenges that need to be met. This paper describes the development and testing of a new drilling fluid designed to meet these challenges. The water-based fluid is based upon two guiding principles, the ability to incorporate the bitumen into the mud itself, and the capability of the system to later break the bitumen from the mud system. Incorporation of the bitumen into the mud is via a direct emulsification and results in zero accretion, virtually oil-free sand from the solids control equipment, fast drilling rates and good hole stability. The post drilling breaker allows for the oil/bitumen/tar to be skimmed from the surface of the drilling fluid allowing for conventional disposal of the liquid fraction. Data from a six well horizontal heavy oil program in Northeastern Alberta shows the robustness and effectiveness of the system. The new oil in water direct emulsion system drilled 1100 meter average horizontal wells 35% faster, when compared to conventional inhibition salt technology based drilling fluids. Highlights include sand from centrifuging operation containing < 0.5% oil, elimination of accretion and common foaming problems, fluid reuse from well-to-well, as well as simple land disposal of liquid mud wastes. Total well costs, drilling fluids costs and disposal costs were significantly less than those wells drilled with conventionally inhibited drilling fluid systems.

Summary Early exploration well tests in the Colville River field (also known as the Alpine reservoir) drilled with water-based mud (WBM) systems exhibited unexplainably high near-wellbore residual skin damage documented by pressure-buildup testing. Typical formation-damage mechanisms, including clay reactions, mechanical damage, and gas trapping, could not explain the damage. Between March 1998 and July 2001, laboratory testing determined imbibition-induced water trapping to be the primary formation-damage mechanism. In-situ water saturation is significantly lower than residual or connate-water saturation, a condition rarely encountered in the field. Lab tests quantified impacts and identified methods to minimize or eliminate formation damage. This paper documents how successful identification of a unique damage mechanism improved drilling results in low-permeability sandstone.

Shales present lower mechanical and drillability challenges, when compared to other common lithology types such as sandstones and carbonates1,2. However the penetration rates (ROP) of drill bits, especially that of PDC bits, do not always reflect this characterization. Research efforts, focusing on shale drillability, have now revealed that bit performance in shales is much more dependent on factors such as depositional depths, mud types and mud weights than it is on hardness and/or abrasiveness3,4. The characteristics and/or magnitudes of these factors, that have adverse effects on bit performance, will be referred to as "negative performance factors" (NPF) in this paper. PDC bits usually drill twice as fast as roller cone (RC) bits in Shales. However, this ROP trend reverses when both bit types are exposed to NPF environments. This paper will identify the causes of poor PDC bit performance when exposed to the influences of NPF environments. It will discuss an innovative technology which has specifically been developed to improve the ROPs of PDC bits in shales, especially when drilled at great depths with weighted water based mud systems. Laboratory and field data, showing the technology's positive effects on PDC bit performance will be presented. Specific laboratory tests, designed to identify operational conditions that enhance PDC bit performance in such applications, will also be discussed.

Owing to the economic, well control and drilling efficiency problems it propagates, preventing or curing lost circulation has evolved into a critical issue for the industry. Accordingly, a less expensive drilling fluid system often is selected for a particular interval because it will mitigate the economic ramifications of downhole losses. Conversely, fluid systems are also chosen solely for their capacity to minimize losses downhole. Regardless of the application, special analyses are required to not only determine specific preventative measures for drilling fluid loss, but also for devising an appropriate treatment program to cure losses should they occur. Recently, specialized and chemically activated cross-linked pills (CACP) designed to stop whole mud loss have been developed and have shown significant advantages over conventional loss circulation methods. This paper describes the development and application of the specialized cross-linked pills for controlling downhole mud loss. The authors will detail the laboratory methods used to formulated appropriate formulations, the placement procedures, and the successful field applications of this latest generation lost circulation control mechanism. As detailed in the paper, formulations of the new cross-linked pills normally are tailored to specific downhole conditions of temperature and pressure to create a barrier between the loss zone and the wellbore. Further, they have been specially formulated to enable pumping through narrow drill pipe, coil, or mud motor dimensions and to "set" in a specific time frame. Chemical activators or retarders to control setting times achieve this. These pills also contain controlled concentrations of particulate sealing agents that can be used selectively to either to bridge the loss zone at the formation face or allow deeper penetration into the fracture.

Deepwater drilling operations require a great deal of planning and logistical support, even under the most ideal situations. When shallow water flow hazards are a concern, the importance of the planning and logistical support increases tremendously. The Green Canyon 288 Intruder Project utilized both conventional and unique methods to control the shallow water flow zones that are prevalent in the Green Canyon area of the Gulf of Mexico. These included the use of sophisticated hydraulics software to maintain the equivalent circulating density (ECD) required to inhibit the flow and prevent losses while drilling to casing point. The operational and logistical considerations and pre-planning that combined for the successful drilling of a prospect on Green Canyon Block 288 with an upgraded semi-submersible drilling rig will be examined in detail. Introduction Drilling riserless in deepwater with the possibility of encountering a shallow water flow zone presents a number of challenges. The severity of problems associated with a shallow flow zone can ultimately prevent deepwater wells from reaching projected casing points and even total well depths.' The technical challenges commonly encountered when drilling riserless intervals are: ○ Logistics - being able to supply enough weighted fluid at the wellsite to drill the interval ○ Preventing bit balling and hole pack-off with cuttings ○ Maintaining adequate hole cleaning in a large sized hole with acceptable rate of penetration ○ Maintaining control of the well and avoiding shallow water flow problems by monitoring ECD at the suspected flow zone as well as at the bit while drilling ahead. In order to drill this interval with a minimum of problems, it was decided to use the weighted mud for the entire section thereby avoiding the risk of encountering a shallow water flow zone with an underbalance of hydrostatic pressure that could result in an uncontrolled well flow. This method, commonly referred to as the Pump and Dump Method, utilizes drilling mud rather than seawater and high viscosity sweeps. Like the seawater/sweep method, the pump and dump method has the mud returns taken at the sea floor. Drilling riserless with weighted mud has been done quite successfully in recent deepwater operations. However, most of these recent operations have been accomplished with the newer, fifth generation drillships that have enormous mud storage capacities relative to older semi-submersible rigs.

Increasing water depth, total well depth, synthetic mud systems and increasing measurement complexity pose unique challenges for real-time data transmission via mud pulse telemetry. In deepwater environments, where the use of synthetic oil-based mud is prevalent, low water temperature significantly increases mud viscosity which reduces the signal strength at surface and makes detection of the signal more difficult. Noise within the mud channel further hinders transmission of downhole data. With rig rates approaching $350k per day and total well depths beginning to exceed 10700 m (35,000 ft), operators cannot afford to drill ahead without good quality real-time downhole data. On recent wells in deep water conditions in the Gulf of Mexico as many as seven different measurement while drilling/logging while drilling (MWD/LWD) tools have been run concurrently. Some of these tools may include the capability to produce real-time images. There is thus an increasing demand for higher data rates coupled with more reliable telemetry to transmit all this data to the surface in real-time. Recent advances in MWD tool design, signal strength prediction, and signal recovery on the surface, using advanced digital signal processing techniques, have made it possible to double telemetry data rates while also reducing error rates in the data received at the surface.

Oil-Base Mud (OBM) systems have been used in the oil and gas industry for many years. Historically OBM systems have contained aromatic compounds. Environmental concerns linked to the use of OBM pushed the industry to develop Synthetic-Base Mud (SBM) systems with no aromatic content. This paper focuses on the use of ester-base mud (EBM). EBM was originally used in the top-hole sections of wells. It is now extensively used to drill the complete range of exploration, development, water source and water injection wells. This paper will demonstrate that EBM has a significant impact on well measurements (FEWD and wireline logging, mud logging, coring, etc.) when compared to Water-Base Mud (WBM) or traditional OBM. Examples derived from offshore and onshore fields in Nigeria will be presented. Local efforts to investigate the effect of EBM, have been carried out in Nigeria by Oil and Service companies. These results seem to indicate that this effect causes a modification of the mud filtrate invasion profile within the formation and results in a complex interaction with the fluid in place. Adverse effects have been observed which have consequences on formation evaluation data and the subsequent static and dynamic reservoir evaluation. A major concern is that Original Oil In Place (OOIP) calculations are systematically reduced. Therefore, on critical wells where formation evaluation is a key issue, the choice of such mud systems needs to be balanced with the potential loss of geological and petrophysical information and the anticipated reduction in drilling cost. A comprehensive study, coordinated by a special interest group, needs to be initiated on a larger scale by the companies concerned. The objective of the study would be to understand the physics and chemistry of SBM on rocks and formation and develop corrections for log and core measurements. This study would benefit the worldwide users of SBM drilling fluids. This paper will discuss the observations and propose a program to better understand the phenomenon and improve formation evaluation accuracy.

Historically, acquiring borehole image logs and resistivity at the bit measurements of useable resolution have been difficult, if not impossible, when using oil-based drilling fluids. Conversely, in many applications, drilling objectives and other performance criteria prohibit the use of water-based fluids, which deliver logs of higher resolution. Azimuthal borehole images in oil-based mud systems are delivered by wireline conveyed ultrasonic measurements or azimuthal density measurements made while drilling. Higher resolution images have generally been out of reach in oil-based systems because the measurement technology used to deliver these services involves passing electric current through a conductive borehole fluid. Resistivity-at-bit devices used for geostopping and geosteering also rely on electric current transmission from the bit to the formation and are optimized for a conductive mud system. In many applications, drilling objectives and other performance criteria prohibit the use of water-based fluids, thus placing high-resolution images, resistivity-at-the-bit, and the high-value applications that these services can deliver out of reach of the reservoir evaluation and well placement teams. This paper describes the development and successful application of a conductive oil-based drilling fluid system that produces water-based logging quality and enhanced geosteering without sacrificing the performance advantages of invert-emulsion fluids. This unique system, employs an electrically conductive continuous phase that provides a high-performance fluid with a conductive mud, filter-cake and filtrate. The authors detail the development of the system, which included a yard test where fluids of varying conductivity were circulated through a test well with formation micro imager response determined and compared against measured conductivity. Further, the authors discuss the application of this new system on the Gullfaks South in the Norwegian sector of the North Sea, where the fluid was used to drill a highly deviated well through complex geological structures. In this application the fluid showed the drilling performance expected from an invert-emulsion oil-based fluid (i.e. high penetration rates, wellbore stability and low torque/drag). Results from formation micro image logs and resistivity-at-bit measurements taken using this fluid are presented and discussed. The authors also review lessons learned in the development and field application of this conductive fluid, and address current limitations and future developments.

A new generation calcium chloride (CaCl2)/polymer-base drilling fluid system has been developed and successfully applied in the deepwater Gulf of Mexico. The system was developed specifically to address the myriad of operational problems associated with drilling the highly reactive, gumbo-laden clays found throughout the Gulf of Mexico. This paper describes the evolution of these systems and the lessons learned during this experience, including mixing and shearing procedures to eliminate the shaker screen blinding seen on wells drilled with first generation CaCl2 systems. The authors will present the application of the newest generation CaCl2 system, which employs a uniquely engineered encapsulating polymer. Among the field trials to be reviewed is one from a newly built drillship, which used the system to drill its debut well in the deepwater Gulf of Mexico. Further, the paper examines the performance of this new system compared with other water-based systems traditionally used to drill similar intervals. Experience from several wells employing calcium chloride/polymer systems and evolutionary modifications to improve their efficiency will be discussed. These sequential improvements have allowed the development of a decision tree to determine optimum applicability.

The North Sea Block 16/7a West Brae and 16/6a Sedgwick fields were discovered in 1975 and 1985 respectively. The developments languished for several years because of limited reserves, unconsolidated sands, and slightly heavy (22 deg API) oil. Advances in horizontal drilling techniques, mud systems, sand control, and subsea completion technology, revived the potential of an economic development during 1996. Infrastructure synergies and utilisation of an experienced core team of six Marathon engineers and one geologist, helped minimise development costs of this subsea tieback to the existing Brae Alpha platform. This paper intends to record the considerations for effective and economic engineering of sand control requirements for the West Brae/Sedgwick wells. Horizontal wells were selected as the best solution to delay coning of water or gas, thereby maximising oil drainage. The goal of the production well design was simply to maximise recovery of hydrocarbons by minimising formation drawdown and sand production. To achieve this goal, emphasis was placed on proper engineering and testing of drill-in fluids and sand screens. The upper completion components were selected based on reliability and ease of installation to minimise costly rig time. Similar engineering emphasis was placed on the injection well design to ensure completion longevity and long term pressure support. Thus far, the implemented completion strategies appear to have met the West Brae/Sedgwick sand control objectives. The designed drill-in fluid system cleaned up quickly and efficiently without the requirement for potential formation or screen damaging breakers. No evidence of sand production was found during clean-up to the rig, or during 16 months production. Furthermore, results of a wireline conveyed production spinner log demonstrated flow contribution along the entire horizontal length of the first West Brae completion, thus increasing the likelihood of proper drainage. Four wells are currently producing to the host platform at a combined liquid rate of 40,000 bpd. Water encroachment has lagged model projections and productivity has exceeded expectations. A single injection well is providing pressure support to the Balder reservoir in both the West Brae and Sedgwick fields. Finally, total development costs for this project have been recovered within 16 months despite a depressed oil product price.

Application of Silicate-Based Drilling Fluid in Tertiary Clays Offshore Norway J.L. Barnfather, SPE, Baroid Drilling Fluids; D.J.M. Bax, SPE, Norske Shell E&P; E. van Oort, SPE, Shell E&P Technology Co.; O.J. Nielsen, SPE, Baroid Norway S.A. Abstract A water-based mud based on soluble silicates has been used to drill through the highly reactive Tertiary clays and marls of the Nordland/Hordaland group and the Ekofisk chalk on two sub-sea exploration wells offshore Norway. The silicate-based fluid was primarily selected for its superior clay and shale stabilizing characteristics and was regarded as an environmentally-friendly alternative to oil-based mud and synthetic-based mud, which are precluded from use by the operator's environmental protection policy. Additional factors were anticipated cost-effectiveness and an expected reduction in total chemicals discharged compared to other WBM's. The performance of the drilling fluid, which actually combines a soluble silicate and a polyglycol for added performance and mud stability, suggests that a new milestone has been reached in finding a cost-effective WBM with low environmental impact to replace OBM's, SBM's and low-efficiency WBM's currently available, in a wider range of drilling applications than had previously been supposed. This paper presents the learning opportunities during these field trials. Data for drilling efficiencies are reviewed which will demonstrate the fluids superior performance compared to other WBM technologies. A cost comparison to mud systems used on offset wells is made, and savings realized against well AFE are presented. Silicate based drilling fluids: General Introduction Silicate-based drilling fluids have been successfully reintroduced in the field in recent years after having been pioneered in the early 1930's and briefly revisited by Darley in the late 1960's. The current generation of silicate-based polymer mud systems contain typically 5–15% v/v of a soluble silicate product, for which the generic formula is given by M2O.xSiO2, where M is Na for sodium silicate and K for potassium silicate and × represents the molecular ratio. Soluble silicates arc generated by either fusing quartz (sand) with soda ash or potash, or by dissolving quartz in NaOH (caustic soda) or KOH (potassium hydroxide) at elevated temperatures. Silicates in stable solutions at high pH (typically 10.5–12.5) usually encompass a variety of different molecular species, ranging from monomers to low-molecular weight oligomers. The negatively charged oligomers will rapidly precipitate polyvalent ions such as Ca++ and Mg++, and may form three-dimensional gel structures when solution pH is lowered. Shale and chalk stabilization. Although the exact mechanisms by which shale and chalk destabilizes are quite complex (see ref. 4), the solution to stability problems appears to be to engineer the mud system in such a way that mud pressure will be confined to the wellbore (i.e. pressure is not penetrating the formation) and that water cannot reach the reactive chalk and clay surfaces. Silicates achieve this by reacting with the Ca++ and Mg++ ions present on chalk surfaces and in shale pore throats and by gelling in the low-pH pore fluids of shales. The precipitates/gels formed will plug and coat the borehole wall, thereby preventing water and mud pressure's from entering the formation. It has been demonstrated that the silicate precipitate/gel in shale pores also acts as an almost ideal semi-permeable membrane, allowing the osmotic flow of water. By using elevated levels of a monovalent salt (e.g. NaCl, KCl) in the silicate-based drilling fluid to suppress water activity, osmotic flow of pore fluid from the shale to the mud may be induced. The lowering of the near-wellbore shale water content and pore pressure can act as a secondary shale stabilizing mechanism, particularly useful in stabilizing weak, reactive clay/shale formations. The addition of K+ to silicate-based fluids in the form of KCl has the additional advantage of removing Ca++ and Mg++ ions from clay surfaces by ion exchange, which can then become available for more rapid precipitation of the silicate oligomers. P. 51^

Minimising filtrate loss into the formation by forming a filter cake with low porosity and permeability near the wellbore region is the key to managing formation damage problem. Visualising and understanding the structure of a filter cake can help formulate a drilling fluid system that provide an effective caking process with reduced water loss. In this study, a technique that identifies the appropriate mud caking process is suggested. It can be applicable to relevant sandstone formations within 2 inches from the wellbore. This identification technique is based on the measurement of filtrate loss, the measurement of the return permeability of cores exposed to selected muds and the visual observation on the micro-level of cake structures of these muds in order to describe them and highlight their merits. A good mud system is the one which have a low filtrate loss, a low return permeability and a filter cake structure close to that of the ideal internal and external filter cake. This study also provides an investigative and comparative look at the internal and external filter cake structures of different muds using the Scanning Electron Microscopy. This technique verified that the glycol and petrofree drilling fluids possess the characteristics and filtration properties of good mud systems. The glycol filter cake structure was superior to those of the solid free /low solid KCl-polymer muds. Scanning Electron Microscopy provided clear and descriptive images of the structures of internal and external filter cakes.

Abstract In the Upper Permian Zechstein Salts, previous attempts to drill a gauge hole to facilitate cementation and prevent the frequent incidents of casing collapse caused by salt movement habitually resulted in stuck pipe. A variety of different mud systems, drill bits and bottom hole assemblies have been used in attempts to achieve gauge hole and overcome the expensive problems associated with stuck pipe. A potassium-magnesium mud system (KMG) resulted in an average of 0.6 stuck pipe incidents per well. When this system was heated and supersaturated (heated KMG), the stuck pipe incidence increased to 1.25 occurrences per well. Use of a synthetic oil-based mud intensified the problem with stuck pipe incidents increasing to an average of 2.5 occurrences per well. Meanwhile, field trials with eccentric bits proved unsuccessful, as it was impossible to drill both the float equipment of the previous casing and the succeeding formation. Further, problems surrounding the unpredictable directional behavior of eccentric bits necessitated costly correction runs. The majority of wells the operator drills employs 53.5 lb/ft of 9 5/8-in. casing set at the top of the Zechstein. Standard drift sizes for this casing is 8.378 in., which historically resulted in the drilling of 8 3/8-in. holes. This paper describes the development and application of a redesigned 8 1/2-in. IADC M332 PDC bit, featuring an undersized (8.375-in.) gauge pad that when run on standard 8 3/8-in. assemblies overcame the costly stuck pipe problems resulting from attempts to drill gauge hole through the Zechstein Salts. With the new bit/BHA combination a special drift specification of 8.5 in. was allowed at no additional cost, which subsequently permitted an 8 1/2 in. cutting structure to be run on standard 8 3/8 in. assemblies. The combination has been used to drill more than 16,400 ft (5000 m) of deviated hole in the Zechstein squeezing salts with no incidents of stuck pipe. This approach was used to drill the longest well in The Netherlands, where 8,200 ft (2500 m) of salt was drilled at 800 to a depth of 20,404 ft (6221 m) at an average of 50.5 ft/hr (15.4 m/hr). In a performance analysis, the authors will show that while mud weights gradually reduce, shoetracks are being drilled successfully and directional objectives are being achieved with predictable performance. Introduction In the early 1990's, it was estimated that stuck pipe incidents were costing the worldwide industry more than $250 million a year. The majority of stuck pipe problems occur in the so-called squeezing salts found in the Zechstein group of Upper Permian evaporites. The Zechstein group is deposited throughout much of The Netherlands, onshore Great Britain, the North Sea and extending into Germany and Poland. The group comprises four major and basically identical stratigraphic sequences - Zechstein 1 through Zechstein 4. The order of precipitation is carbonates (calcite and dolomite), sulfates (anhydrite and gypsum), chlorides (halite, "rock salt") and lastly a mixture of chlorides and sulfates (carnalite, sylvite, kieserite and bischofite). The latter sequence is generally referred to as the squeezing salts. As Swale amplified, the global problems associated with salt squeeze occur during the drilling process as primary deformation. Secondary deformation occurs over a period of months after the well has been cased and cemented. Drilling a production well through massive salt sections that can be as thick as 900 m frequently results in a tight hole, and ultimately stuck pipe. P. 815^

Abstract The oil-in-water emulsion drilling fluids, prepared by adding 5 12% mineral oil (or diesel) to water-based muds, have been widely used for stuck-pipe prevention in Shengli Oilfield. In some cases, the emulsion stability of this kind of mud systems is not strong enough to meet the requirements of drilling operations. To overcome this drawback, a solid emulsifier which is characterized by its very small particle size and the special wetting behavior (slightly water-wet), has been developed and successfully applied to improve the emulsion stability and other performance of these drilling fluids. Prior to the development of this technology, an extensive study dealing with the influence of various kinds of finely divided insoluble solid particles on the emulsification of oil and water was carried out. The substances used include bentonite, organophilic clay, kaolinite, barite, two kinds of calcium carbonate with different particle size, two kinds of silica with different wetting behavior, and the new solid emulsifying agent. Both emulsion stability experiments and drop coalescence experiments were performed to evaluate the contribution of these particles to emulsification. The measured final emulsion volume left after 12 hours and the half-life for water and oil drops were used as the measures of emulsion stability. The experimental data show that the type, size, concentration and wettability of the particles, and the presence of some surfactants control the type and stability of emulsions for a given oil/water system, and the fine particles of the solid emulsifier provide the most effective stabilization to water-continuous emulsions compared with other kinds of particles. Meanwhile, it can be observed that these particles also stabilize oil-continuous emulsions effectively in some cases since their wetting behavior is close to neutral. The newly developed oil-in-water emulsion mud stabilized by the solid emulsifier has become one of the major mud systems used in directional and horizontal well drilling in this oilfield. In addition to its improvement on emulsion stability, this solid emulsifier has proven to enhance wellbore lubrication and to be of benefit to the control of rheological parameters and filtration. The field applications of the emulsifier, and the typical formulation and properties of the mud system are reported in this paper. Introduction It has been well known that the fine solid particles existing in oil/water interfaces can stabilize emulsions. Many investigators presented the results on the effect of various finely divided solids, and the combinations of these solids and surfactants, on the stability of water/oil emulsions. Some of them discussed the mechanism by which particles stabilize emulsions. For example, Gelot et al. observed that water-wet particles such as Ca-bentonite tended to stabilize oil-in-water emulsions, while oil-wet particles such as carbon black tended to stabilize water-in-oil emulsions. Tadros and Vincent concluded that particles will tend to remain at the interface when the three-phase contact angle equals to 90 and play a role in preventing drop-drop coalescence in emulsions. Tambe and Sharma presented the experimental data to show the influence of various colloidal particles, such as calcium carbonate, barium sulfate, bentonite and carbon graphite on the stability of oil/water emulsions and claimed that these solids stabilized emulsions both by providing steric hindrance to the coalescence of oil and water droplets and by modifying the rheological properties of the interfacial region. They also thoroughly summarized the results of previous investigations. Most results described above were derived from fundamental work and did not involve with practical applications. Unlike the previous studies, the main objective of this study is to develop a solid emulsifier to improve the performance of drilling fluids. P. 561^

Abstract The primary cement job is critical to the success of a well completion. In many instances, the use of present spacer technology has resulted in mud contaminated cement. This paper discusses how the ARCO designed spacer system exhibits exceptional performance to clean out the wellbore and improve the quality of the cement job. Field examples from Offshore Gulf of Mexico show that this cleanout technology, together with pipe centralization and proper job execution, has resulted in good downhole placement of the cement slurry with minimal mud contamination. This success not only has drastically reduced the need for remedial cement work, but also has made the cement bond evaluation straight forward. This spacer technology has been successfully applied in water-based, oil-based and synthetic-based mud systems. Furthermore, the use of this spacer technology is now being expanded to other ARCO operations around the world. Introduction Past Experience. A good primary cement job across a productive horizon has been considered by many to be important and considered by others to be one of the most critical points at the end of drilling and the beginning of the completion stage in an oil well construction. In the U.S. Gulf of Mexico (GOM) offshore and Gulf Coast (GC) onshore, poor cement jobs have been shown to be very costly especially in areas where formations have a distinct oil-gas-water contact and isolation is desired completely across a pay interval. Poor cement and the lack of zonal isolation has resulted in expensive squeeze repair operations, reduced production rates, premature watering out, failure of stimulation treatments and other problems that has ultimately increased operating costs and cause loss of reserves. Past experience concerning unsatisfactory cement quality or a cement evaluation log that is not straight forward has caused many problems on new completions. The normal flow of the completion operation is forced to halt or is slowed down to a crawl with expensive services and equipment put on standby while the cement evaluation log is evaluated and reserves and chance factors are examined by the completion team. Often times the cement evaluation log is played back using revised parameters to enhance the quality of the log. Still other times, a decision is made using the best information available at the time risk weighting reserves versus cost to repair. Later in the life of a well, increased water production due to poor zonal isolation has caused wells to load up, cease natural flow and is placed on artificial lift resulting in additional facility cost and often requiring a rig recompletion to install gas lift valves. Excessive water production puts more pressure on the surface facility capacity and increases water disposal costs and the environmental effects. Squeeze operations in older dual and selective gravel packed completions in high cost areas like offshore GOM, have been shown to provide short lived success with premature failure or are too expensive to even attempt, resulting in zonal abandonment and lost reserves. Identifying Contaminated Cement. Cement Bond Logs (CBL) are used to determine the quality of the cement. The standard interpretation for CBLs are based on the compressive strength of the cement. If the cement becomes contaminated, the compressive strength is lowered. This decrease in strength will cause the amplitude from the CBL to be higher than expected. This increase in amplitude is usually confused with a cement channel. To avoid this confusion, a Cement Evaluation Log is necessary to look at 5 to 60 degree segments around the casing. If the cement around the casing has uniform quality and the compressive strength is above 200 psi then this indicates cement contamination with adequate cement strength for zonal isolation. P. 727

Quartz arenites are very clean quartz sandstones with unusually high permeabilities for any given porosity. This is attributed to the presence of large, clean pores which are often well connected. These large pores are susceptible to drilling damage, mainly from the invasion of solids. This paper presents both laboratory and field data on the development of drilling fluids to minimise damage in quartz arenites. The required changes in field mud engineering practices, to achieve improved well performance, are discussed. Field experiences are presented, including the impact of the modified mud systems and engineering practices on the resulting skin factors.

Abstract This paper describes a major joint industry study into the effectiveness of mud clean-up techniques for horizontal wells involving eight oil and service companies. Experimental work was carried out on a small scale laboratory clean-up rig to quantify mud damage and test breaker effectiveness. Large scale flow loop testing was used to evaluate overall clean-up techniques including displacement efficiency and damage to pre-packed screen completions. Tests on a wide variety of mud systems showed surprisingly little difference in the performance, from a formation damage perspective, on clean sandstone cores. Oil based muds were, however, found to produce less damage than water based muds. A range of breakers were tested with each mud system. There was a large variation in the results of breaker testing. with breakers, unexpectedly. sometimes causing an increase in the pressure required to break through mud filter cake and/or formation damage. Whole mud was found to cause significant damage to pre-packed screens; this damage was sometimes, though not always. removed during clean-up. Poorly centralised screens were found to result in large amounts of mud and debris on the low side of the hole. Introduction Horizontal wells are increasingly used in field developments to maximise well productivity, access reserves, or reduce water and gas coning by reducing drawdown. These benefits of horizontal wells can only be attained if all well sections are flowing without significant near wellbore damage. Most horizontal wells are completed open hole i.e. without a cemented and perforated liner. These open hole horizontal wells, which are typically completed with prepacked screens or slotted liners, differ from conventional cased and cemented liners in two important ways:–Oil or gas must be produced through mud filter cake and mud induced formation damage as perforations are not shot through the damaged layer.–Sand face completions such as pre-packed screens designed for sand control are themselves susceptible to damage from the mud system. A variety of specialised mud systems and clean-up techniques are used to try to minimise mud damage or remove it during well completion operations. The most common approach is to use a brine based mud system with an acid or water soluble weighting agent and then use acid breakers to dissolve filter cake solids and polymers. Brine is used to reduce mud solids loading and new systems are continuously being developed to extend this low-solids approach to higher mud weights; however, little work has been carried out to establish the need for, or the effectiveness of clean-up procedures. Radically different approaches to clean-up have been applied to the same mud system with apparent success. Also, wells in which little or no clean-up was attempted, have been completed with minimal damage. To address these issues an eight partner joint industry project was set-up to investigate mud clean-up in horizontal wells. A programme of experimental work has been conducted that studied the clean-up of a number of different mud systems, using both laboratory and large scale equipment. Additionally, large scale experiments were carried out to study the displacement process in horizontal wells. The objective of the project was to try to understand the parameters which control mud damage and its clean-up with breaker systems and thus allow a more systematic approach to fluids selection and the design of horizontal well completion operations. This paper describes the main findings of this joint industry project. Work Programme The work programme for the joint industry project consisted of seven test series. Each of the first six test series investigated the damage and clean-up behaviour of a specific mud system with a number of breaker systems. Both small scale laboratory tests and large scale flow loop tests were used. The final test series was a displacement study. P. 801

1.0 Introduction 1.1 Abstract Efficient drilling technology is essential to meet the needs of the oil industry. Both the challenges of new oil provinces, especially in offshore waters, and the demands for efficient environmental protection have driven the development of new technology. Drilling mud is a key factor influencing drilling technology used in modern drilling operations. New oil industry developments involve directional and horizontal drilling as well as drilling in frontier areas at greater and greater depths. Such capabilities and conditions demand careful attention to the selection and engineering of efficient mud systems. Spent drilling fluids and drill cuttings are among the most significant waste streams from exploration and development activities in the oil and gas industry; they pose a serious and costly disposal problem for offshore operators who must barge spent mud and cuttings to shore for land disposal if they do not meet U.S. Environmental Protection Agency (EPA) discharge limitations or permit requirements. Suppliers of mud systems have responded to this problem. Since 1990, several non-toxic, biodegradable synthetic-based muds (SBMs) with desirable performance and environmental characteristics have entered the market. However, EPA regulations apply mud technology that was available when the regulations were developed, namely water- and oil-based muds (WBMs and OBMs) While EPA requirements appear to have been a major driver behind the development of SBM, now concern is focused on the inhibiting effect of discharge limitations on use of alternative mud technologies This paper examines and describes SBM systems recently developed as substitutes for conventional drilling muds. Initially, background information on drilling mud is presented to provide an overview. The paper identifies the advantages and disadvantages of alternative drilling muds and assesses their comparative environmental impact and cost/benefit. The paper also characterizes the regulatory factors which affect the introduction and widespread use of innovative alternative mud technology. Finally, the paper assesses the approach of EPA in administering effluent limitations guidelines (ELGs) and its impact on innovative technology development. It recommends areas of further study and suggests regulatory process improvements to encourage the development and use of alternative mud technologies. P. 457

SPE Members Abstract Oil base drilling fluids are imperative to the success of GUPCO's Gulf of Suez drilling operations. Protecting the environment while utilizing these environmentally unfriendly drilling fluids has proven to be a challenge. This paper describes how GUPCO championed this challenge. Early attempts to drill the reactive shale and low pressured-high permeability sands exposed in the lower Tertiary with water base drilling fluids resulted in wellbore instability, differential sticking, and loss of hole. These drilling problems were all but eliminated with Oil Base drilling fluids (OBM). Furthermore, OBM provides the lubricity that is essential to the success of high angle, horizontal, three-dimensional, and long reach wellbores, which are becoming the norm rather than the exception at GUPCO. GUPCO drilling has pursued several means to satisfy drilling needs and environmental concerns;slurrification and downhole injection of OBM cuttings,hauling OBM cuttings to shore for disposal, 3) utilization of OBM alternatives. Slurrified cuttings have been injected below surface casing via the annulus between surface and intermediate casing strings, or in the case of the SIDKI re-development project, an injection well was drilled. Injection guidelines, procedures, and injection results are presented in the paper Oily cuttings have been collected in containers on the rigs and hauled onshore for disposal. Drilling rigs in the GUPCO fleet have been modified to handle the OBM and properly collect the oily cuttings. The paper describes the rig modifications for zero discharge of oily cuttings, including the oily cuttings collection process. Due to the environmental concerns associated with OBM, water based inhibitive mud systems have been attempted in the GOS. Cationic Brine Fluid (CBF) and Partially Hydrolyzed Polyacrylamide polymer (PHPA) drilling fluids have been utilized as OBM alternatives. The results and conclusions are included in the paper. Introduction At the beginning of 1993, GUPCO set a Business Plan Objective to "Ensure That GUPCO's Operations Protect the Egyptian Environment". The Drilling Group established a goal to reach "zero oil drill cuttings and wastes discharge by year-end 1993". The vast majority of the oily cuttings and wastes generated during 1993 were either hauled to shore or injected downhole. During 1993 nearly 91,000 ft of hole was drilled using OBM, creating an estimated 14,638 bbls of oily cuttings and wastes, see Table #1. By year end all rigs had been modified to handle/contain OBM and oily cuttings. Systems were put in place to either haul the cuttings to shore for disposal or offshore downhole injection. P. 209

A recently developed, environmentally safe, water-based drilling fluid has been given its first field trials. The successful field tests have shown that the fluid is indeed very shale stabilizing, has the ability to solve some mud related drilling problems, is easy to formulate and maintain, and is non-hazardous and environmentally safe. These results have corroborated the laboratory testing which had shown that the fluid stabilizes shales by the same mechanism as does oil-based fnuds1. The drilling fluid, which is based on methylglucoside (MEG), thus has the potential to replace oil-based drilling fluids in many operational areas. The use of this drilling fluid could reduce or eliminate costly disposal of oil contaminated drilled cuttings, minimize health and safety concerns, and minimize environmental effects.

SPE Members Abstract Esso Australia Ltd. (EAL) has been drilling deviated wells in Bass Strait (see Figure (i)) since 1968. Recent technological developments have been employed on the Mackerel Infill Drilling Project, that have significantly improved EAL's ability to drill Long Reach (LR) / Extended Reach (ER) wells more economically and consistently. The more notable achievements have been:–Advancements in hole condition reporting, utilising torque and drag monitoring;–The successful use of non-rotating drillpipe rubbers to reduce surface torque to acceptable levels;–Deeper casing setting depths, to minimise torque and drag, and to reduce time-dependent hole problems;–The use of inhibitive / encapsulating mud systems for control of reactive clays / shales; and–Use of wellbore stability modelling. These advancements have helped EAL to drill 50% greater metreage than was expected in 1993, at 16% lower cost per metre. This paper chronicles the engineering decisions behind these advancements, their applications in the field, the success / failure story on Mackerel to date, and how these developments have been incorporated in EAL's future well planning. Introduction The original development drilling of the Mackerel (MKA) field took place between 1976 and 1980. In late 1992, an eighteen well infill drilling program began, finishing in mid 1994. Prior to commencing on the infill program, the platform rig (which has been drilling in Bass Strait since 1988) had just completed a very successful infill drilling program on West Kingfish (WKF) field, where several Bass Strait records were set. The MKA wells, like other Bass Strait wells, penetrate three major formations : the Gippsland marl, the Lakes Entrance shale, and the Latrobe sandstone/shale. The Lakes Entrance formation is a reactive, highly dispersive cretaceous shale, with a surface area of 250 m2/gm. It's stability is highly time-dependent. The Latrobe sandstone consists of some extremely permeable sands >10 darcies), with interbedded shale, siltstone and occasional pyrite stringers. The oil bearing sands within the Latrobe are normally pressured. There are no over-pressured zones in the MKA field. Water based drilling fluids are used to drill all wells, with intermediateand production holes predominantly drilled with KCl/PHPA polymer muds. P. 349^

SPE Members Abstract An analysis of three-cone rock bit runs using extended jet nozzles (EN) in the Middle East Region is presented. presented. These runs were made from 1982 to 1984 in several Middle East countries. They represent wells drilled onshore and offshore, vertical and deviated, using oil and water based mud systems. The improvements in performance gained by enhanced hole cleaning with extended nozzles are well documented. This feature has been widely used in the South East Asia - Far East region and in certain areas of the continental U.S.A. and Alaska since the mid - 1970's. The result of the EN runs in the Middle East correlate well with results in the proven areas elsewhere in the world. Penetration rate increases over regular jet bits of 7-80% have been recorded. The high daily rig costs characteristic of Mideast drilling operations make it fairly easy to show a cost per foot decrease with only slight increases in per foot decrease with only slight increases in performance. performance. The increased bit cost due to the EN feature is found to be virtually negligible. Introduction It is a well accepted fact that improving bottom hole cleaning can increase rate of penetration and thus lower drilling cost. Extended jet nozzles enhance bottom hole cleaning over regular jet bits by placing the nozzle discharge in close proximity to the hole bottom. This nozzle placement comes from theoretical studies showing that impact force is inversely porportional to distance from a jet nozzle. This distance is usually within six nozzle diameters (Figure 1). A much higher percentage of the nozzle discharge fluid velocity and energy is available to remove and prevent regrinding of cuttings, thus improving ROP over conventional jet configurations. Based on early work by Shell in the 1960's, Feenstra pursued further field drilling experiments in Holland pursued further field drilling experiments in Holland which provided evidence that improvement in drilling rate could be achieved by the use of extended nozzles. In 1978 Pratt, in a milestone paper, showed that extended nozzle bits gave an average of 28% increase in penetration rate in the gulf coast region, U.S.A. Robbibaro reported extended nozzle success on the north slope of Alaska in 1979, and Zinger in 1983 reported that over 550 EN bits had been dulled in S.E.Asia with ROP increases of 20-36%. The Zinger paper reported that only a small number of mechanical paper reported that only a small number of mechanical failures had occurred, owing to either a severe dull condition of the bit or to the use of an incorrect bit breaker. In 1970, Shell Oil Company and Smith Tool began work that culminated in the improved extended nozzle designs now available. Today, EN bits provide consistent high performance in a variety of formations with both milled tooth and carbide insert (TCI) rock bits. Mechanical problems such as tube breakage and nozzle washouts have largely been eliminated. Extended nozzles are now available on bit sizes 1712 in. (444.5mm), 12 in. (311.2mm), and 9.7/8 in. (250.8mm). All of the above sizes feature interchangable jets on both the extended tubes and center nozzle to allow optimization of hydraulic parameters. Center jet nozzles are often used in conjunction with extended nozzles to provide cleaning for the inner tooth rows and to impart momentum to the fluid in the dome area of the bit. Special diffusion center jets are available which distribute fluid over a large area to maximize tooth cleaning (Figure 2). P. 111

Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere is usually granted upon request provided proper credit is made. Abstract In recent years the development of more sophisticated mud systems In the North Sea has drastically changed the concept of mud solids control on the rig. Getting a "better handle" on mud costs and reducing the pollution associated with losses on surface have become major concerns for the Operator and have resulted in a focus on the efficiency of mud mechanical treatment equipment. This paper shows how an extensive and full scale test campaign has allowed a Drilling Contractor to develop new methods for the optimization of the use of shale shakers / mud cleaners / centrifuges. After a brief review of laboratory results, it describes field trials and shows how the use of sophisticated measurement devices and on site computer evaluation can lead to significant improvements in typical North Sea system operations. Introduction A review of published literature and discussions with the major equipment manufacturers convinced Sedco Forex that there was a need to improve the theoretical understanding of Mud Solids Treatment and to raise the level of expertise needed to operate a rig system. In 1985, Sedco Forex decided to initiate an extensive research programme on Mud Solids Control Process. This programme was conducted in three different steps.Full Scale Laboratory Testing of Solids Control Equipment using the Schlumberger Cambridge Research Centre facilities. Definition of representative "performance curves" for each piece of equipment.Field Testing of the Equipment in the North Sea. Verification of test results as per Step 1. Definition of optimized sample taking methods and measurements.

Abstract Zechstein wells in Germany require water based drilling fluids with filtration control additives which are (1) extremely salt and hardness tolerant as the Calcium/Magnesium content in the mud filtrate may run up to 140, 000 ppm and (2) which function in the temperature range up to at least 350°F (177°C). Use of a new sulphonated polymer filled a gap in existing fluid loss additives for high salt and high hardness environments and resulted in improved proved mud performance and cost savings. Major benefits came from a synergism of the novel polymer with starch and cellulosic materials like e.g. CMC or PAC. Minor additions of the new polymer yield an average gain in thermal stability of 50°F (25°C) for starch and CMC or PAC, resp. Field experience with a combination of starch and the novel fluid loss polymer indicate a completely Calcium/Magnesium tolerant, up to 290°F (143°C) stable and inexpensive mud system. Thermal stabilization of CMC/PAC through combination with the novel polymer also was successfully field proven. Introduction As a result of the oil price collapse last year, exploration for oil in West Germany has practically ceased. However, considerable gas drilling with depths between 10,000 and 20,000 ft (appr. 3 000 - 6 000 m) remained. Most of this deep exploration is done in North-East and northern parts of West Germany where huge salt structures are very common. Among the different salt zones, the Zechstein formation is well-known for creating severe drilling problems due to its high content of divalent cations. The water based drilling fluids used in such Zechstein wells often encountered severe performance problems or created excessive costs. In our paper we report on some new development regarding improved fluid loss control additives used in deep Zechstein wells. The introduction of a novel sulphonated polymer with exceptional salt and Calcium tolerance greatly enhanced drilling mud performance and reduced costs in such wells. The paper also presents some basic field experience in German Zechstein drilling. Zechstein Drilling Problems The Zechstein formation spreads from North-East Germany into Holland and the Southern part of the ·North Sea (UK and Denmark Sector). Besides sodium chloride, this zone often contains excessive amounts of Calcium and Magnesium chlorides or sulphates, respectively, which are the reason for most drilling problems. E.g. in a typical Zechstein brine, up to 140,000 ppm of Calcium/Magnesium hardness are found which is even worse than what operations in Mobil Bay area in USA used to see. The ion analysis for a typical Zechstein brine influx which we obtained 3 years ago in a German exploratory well is given in Table I.