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Background: The tumor necrosis factor (TNF) superfamily cytokine TNF-like protein 1A (TL1A) and its receptor DR3 are essential for diverse animal models of autoimmune disease and may be pathogenic in rheumatoid arthritis (RA). However, the relationship of TL1A to disease duration, activity, and response to anti-TNF and other therapies in RA is not clear. Methods: We measured soluble TL1A in synovial fluid (SF), serum, or plasma from RA first-degree relatives (FDRs) and in early RA and established disease. We measured the effects of anti-TNF and methotrexate (MTX) therapy on circulating TL1A from multiple independent RA treatment trials. We also determined the ability of a blocking anti-TL1A antibody to inhibit clinical disease and articular bone destruction in the murine collagen-induced arthritis (CIA) model of human RA. Results: Soluble TL1A was specifically elevated in the blood and SF of patients with RA compared to patients with other diseases and was elevated early in disease and in at-risk anti-cyclic citrullinated peptide (CCP) (+) first-degree relatives (FDRs). Therapeutic TNF inhibition reduced serum TL1A in both responders and non-responders, whereas TL1A declined following MTX treatment only in responders. In murine CIA, TL1A blockade was clinically efficacious and reduced bone erosions. Conclusions: TL1A is specifically elevated in RA from early in the disease course and in at-risk FDRs. The decline in TL1A after TNF blockade suggests that TL1A levels may be a useful biomarker for TNF activity in RA. These results support the further investigation of the relationship between TL1A and TNF and TL1A blockade as a potential therapeutic strategy in RA.

Summary A new downhole annular pressure-while-drilling (PWD) tool has been applied recently to assist in drilling the reservoir section on the Statfjord field, offshore Norway. For drilling success in these high-angle wells it is critical to maintain the mud weight and equivalent circulating density (ECD) within safe operating limits defined by the formation fluid, collapse, and fracture pressures. Operating outside these limits historically has led to expensive lost circulation, differential sticking, and packoff incidents. Monitoring the actual downhole pressure in real time with a PWD tool, rather than relying on inferred pressures from predictive models, has allowed the operator to stay within and to better define these operating limits. The operator used this improved hydraulics information to avoid pressure-related hole problems, to optimize drilling practices, to test hydraulics models, and to obtain a greater understanding of the formation pressure limits. Introduction The majority of drilling downtime results from hole problems principally including lost circulation, formation fluid influx, hole collapse, differential sticking, and poor hole cleaning. Such events usually lead to time-consuming and expensive incidents such as lost mud and downhole tools, well-control incidents, stuck pipe, and stuck casing. It has been estimated that these problems account for about 10 to 15% of drilling operations time in the North Sea. Most drilling hole problems occur when the safe operating pressure limits are exceeded. These limits are defined by the pore, collapse, and fracture pressures. They are typically determined from offset well data, either by modeling or by certain measurements made while drilling the well (e.g., leakoff tests, formation tests). If the stresses imposed during drilling are allowed to exceed safe pressure limits, hole problems are likely to occur. The pressure imposed is defined by the mud weight plus or minus any dynamic pressures resulting from pipe movement (swab/surge, rotary) and fluid flow (ECD, breaking the gel strength). The static mud weight is traditionally measured at the surface, and the dynamic effects are estimated with hydraulics models. Additional hole problems can occur if the conditions are insufficient to remove the drilled cuttings from the hole. Poor cuttings removal (hole cleaning) often results in excessive reaming times, packing off, and stuck pipe. This paper describes the development and use of a PWD tool that directly measures the actual stresses imposed on the formation while drilling, and can give indications of the suspended cuttings load. The results, collected over a period of nearly 2 years, have produced a large amount of data. Some of the different hydraulics phenomena observed are discussed, plus an example of how the PWD tool has been used to change drilling practices and improve drilling performance on the Statfjord field. Finally, results are compared with standard hydraulics models (Bingham, yield power law) and an operator in-house program (MudCalc). The Statfjord Field More than 140 wells have been drilled from the three Statfjord platforms. These are producing from three reservoirs: the Brent group, the Statfjord formation, and, more recently, the Dunlin group. Many of these wells are extended-reach-drilling (ERD) wells, including several previous world records.1–3 The large number of high-inclination, ERD, and horizontal wells have required a strong focus on hole cleaning and ECD considerations. In particular, the Brent group is a pressure-depleted, Jurassic sandstone reservoir that has occasional brittle coal layers. These coal layers require special care not to exceed their low fracture strength. At the same time, the mud weight must exceed the collapse pressure of interbedded shales (Fig. 1). On several occasions, the coal has fractured and severe mud losses that were difficult to cure occurred. Recent field drilling has concentrated on the eastern crest where a faulted disorganized zone has more uncertain geology and pressures exacerbating this problem. An operator in-house hydraulic simulation program (MudCalc) has historically proved useful in avoiding extreme ECD values arising from viscous-mud rheologies. It has helped establish ECD limits for these coal layers based on historical fracturing incidents. The program takes into account a simple hole/string geometry, bit-pressure loss, assumed pressure loss through BHA components, mud weight, and rheological properties. Missing from this model have been temperature and pressure effects on mud properties, eccentric pipe position, breaking of mud gels, overgauge hole, lateral pipe movement, and pipe rotation. New drilling fluids based on synthetic oils may also have varying density and rheological properties under downhole conditions that have proved difficult to model in realistic drilling situations. As a result of these known shortcomings of the available hydraulics models and the desire to verify the calculated ECD, it was decided to run a recorded PWD tool. PWD Tool History The PWD tool used for this work was originally developed in Canada for underbalanced drilling applications. Annular fluid is ported through a drill collar to a downhole recording pressure gauge that, in later versions, was connected to a measurement-while-drilling (MWD) tool for real-time data transmission. Ruggedized versions of gauges originally developed for production services are used. These are temperature compensated and have an accuracy of 10 psi over a 0-to-20,000-psi pressure range. The tools and gauges have proved to be very reliable, and calibrations have shown that data quality has always been well within specifications. Recorded and real-time versions have now been developed for 3 1/4-, 4 3/4-, 6 3/4-, 8-, and 9 1/2-in. collar sizes. Raw absolute pressures are converted to an equivalent mud weight (EMW) by use of survey and depth information, and the sensor is typically placed 5 to 30 m behind the bit. Higher pressure losses would be expected at the bit, but it has been calculated that the pressure loss between bit and sensor is negligible. The capability to measure downhole pressures has been in many MWD tools for some time, but use has largely been restricted to measuring the differential pressure across the BHA for monitoring motor and MWD performance. Recorded downhole pressure gauges have occasionally been run to verify hydraulics models in particular situations.4–10 However, over the past 2 years, as increasing PWD data have been collected, the value of this information has been demonstrated and real-time PWD tools have become commercial. PWD Results It was apparent from the initial PWD measurements that existing assumptions and hydraulics models did not fully account for all the phenomena observed. This often led to an underestimation of the pressures imposed on the formation. The following examples are from the Statfjord field, with a few additional examples from the nearby Gullfaks field (Figs. 2 through 10). Tables 1 and 2 show details of the well geometries and mud properties.

A new down-hole annular Pressure-While-Drilling (PWD) tool has recently been applied to assist drilling of the reservoir section on the Statfjord Field, offshore Norway. In these high-angle wells it is critical for drilling success to maintain the mud weight and Equivalent Circulating Density (ECD) within safe operating limits defined by the formation fluid, collapse, and fracture pressures. Operating outside these limits has historically led to expensive lost circulation, differential sticking, and pack-off incidents. Monitoring the actual down-hole pressure in real-time with a PWD tool, rather than relying on inferred pressures from predictive models, has allowed the Operator to stay within and better define these operating limits. The Operator used this improved hydraulics information to avoid pressure-related hole problems, optimise drilling practices, test hydraulics models, and obtain a greater understanding of the formation pressure limits. Introduction The majority of drilling downtime results from hole problems. These principally include those of lost circulation, formation fluid influx, hole collapse, differential sticking, and poor hole cleaning. Such events usually lead to time-consuming and expensive incidents such as lost mud and down-hole tools, well control incidents, stuck pipe, and stuck casing. It has been estimated that these problems account for about 10–15% of the drilling operations time in the North Sea. Most drilling hole problems occur when the safe operating pressure limits are exceeded. These limits are defined by the pore, collapse, and fracture pressures. They are typically determined from offset well data, either by modeling, or by certain measurements made whilst drilling the well (e.g. Leak-off Test, Formation Tests). If the stresses imposed during drilling are allowed to exceed the safe pressure limits, hole problems are likely to occur. The pressure imposed is defined by the mud weight plus or minus any dynamic pressures resulting from pipe movement (Swab/Surge, Rotary) and fluid flow (ECD, breaking the Gel Strength). The static mud weight is traditionally measured at surface and the dynamic effects are estimated using hydraulics models.

Drilling in tectonic active areas always faces NPT related to wellbore instability problems, which are very difficult to predict without a clear understanding of the local and regional stresses magnitude and orientation and their impact on any wellbore trajectory. Ecopetrol S.A. has experienced those problems in the Apiay-Suria areas in the Llanos Orientales basin over the last 20 years. In order to optimize the drilling process by eliminating the NPT related to wellbore instability, a 3D geomechanical model was built integrating the geological structural model with all relevant well information such as wireline logging data and drilling reports. Data from more than 40 wells was used to build several 1D individual geomechanical models. To avoid missing local tectonic effects on the stress field, offset wells close to and away from the main faults crossing the fields were selected. To constrain the orientation and magnitude of the in situ stresses, image data was extensively analyzed to pick wellbore failure (breakouts and induced fractures) while drilling. Wireline logging was used as insightful information to calculate overburden, rock strength and to understand the pore pressure generation mechanism. The 3D model was built using formation tops, faults geometry, reservoir pressure and hydraulic fracturing data. By applying geostatistical techniques on the individual wells’ 1D models, a 3D volume of stresses and rock properties was obtained. The comparison of the 3D results with real data measured in a recent well drilled at the edge of the 3D cube showed amazing one-to-one similarity in all the formations from the reservoir to surface. The new drilling campaign has started using the 3D model for wellbore stability analysis and the results are showing that the associated geomechanical risks to drill the wells in the area have been properly addressed, and a much better drilling experience has been obtained, taking out the guesswork from the process.